Mark Ferchau - Executive Vice President and Director of Engineering and Operations

Analysts

Kim Pacanovsky – Collins Stewart

Joe Allman – JP Morgan

Ellen Hannan - Bear Stearns

Stacy Nieuwoudt – Tudor Pickering

Ron Mills - Johnson Rice

Bruce Brewster – Brewster Asset Management

Richard Tullis - Capital One Southcoast

Dan Mcspirit – BMO Capital Markets

John Freeman - Raymond James

Mike Tapp – Longhorn Capital

Operator

Welcome to the first quarter 2008 Good Petroleum earnings conference call. (Operator Instructions) I would now like to turn the presentation over to your host for today’s call Gil Goodrich, Vice Chairman and CEO.

Gil Goodrich

I’d like to begin by introducing the management team of Goodrich that’s here on the call with us this morning starting with Pat Malloy the company’s Chairman of the Board, Robert Turnham our President and Chief Operating Officer, David Looney our Executive Vice President and Chief Financial Officer and Mark Ferchau our Executive Vice President and Director of Engineering and Operations.

If you’ve not received a copy of the earnings release we made after the close yesterday you can find one on our website at www.GoodrichPetroleum.com or feel free to call my personal assistant, she’ll be happy to e-mail or fax you a copy. As is our practice we’d like to remind everyone that some of the comments we may make and answers we may give to questions during this teleconference call may be considered forward looking statements that involve risks and uncertainties and we have detailed those for you in our SEC filings.

We are very pleased with the first quarter operating results as we met or exceeded a number of internal benchmarks. The results reported for the first quarter were achieved by our team’s efforts and focus on the fundamentals. Specifically we were making progress in reducing drilling cycle times allowing us to drill additional incremental wells and have reduced costs.

Our completion team’s rapid response in efficient well stimulation and completion program is allowing us to move gas to market sooner and our operating teams focus on reducing per unit lease operating expenses resulted in improved numbers in the quarter. Production volumes exceeded the high end of our expectations and grew at a very robust 15% sequentially over the fourth quarter of last year to a record level of approximately 58 million cubic feet of gas equivalents per day.

A number of factors contributed to the better than expected production performance during the quarter including improving results from our in-field focus plans and drilling activities at Minden and South Henderson fields as well as increased activity and performance in the Angelina River trend from both operated and non-operated wells.

The slower production volume growth coupled with improving natural gas prices led to record quarterly revenue of $46.4 million. In addition and approximate $1.00 per Mcf equivalent reduction in overall per unit costs led to operating income of $3.6 million in the quarter and flat to lower cash costs contributed to record levels of cash flow with record EBITDAX of $32.3 million.

The first quarter cash flow growth has off to an extremely good start towards reaching our internal projection for cash flow for full year 2008. The improving levels of cash flow will assist us in funding a greater percentage of our planned 2008 capital expenditures.

In addition, our senior bank group has completed their review of our year end proved reserves and revised the borrowing base under our senior credit facility to $175 million. The revised borrowing base with the support of our senior bank group and our growing cash flow provides us with ample flexibility to fund our aggressive 2008 development program.

In that regard, we set a record pace of drilling by conducting drilling operations on 41 gross wells during the quarter. We continue with a minimum of one rig working full time for the entire quarter in each of our core areas including North Minden, Beckville, Bethany-Longstreet and South Henderson as well as the increased activity in the Angelina River trend where we maintained approximately four rigs running including both operated and non-operated wells.

In the Angelina River Trend we continue to exploit both the Travis Peak formation doing vertical wells with approximately 30 Travis Peak wells planned for the year and the James Lime formation using horizontal drilling technology where we continue to expect to drill 15 to 20 James Lime wells during 2008.

In addition to our core operation we also moved very quickly in response to the emerging Haynesville Shale plate drilling our initial vertical Haynesville test on our approximately 28,000 gross acre position in the Bethany-Longstreet field located in Caddo and DeSoto Parishes of Northwest Louisiana. Our initial Haynesville well, James Cook number one encountered approximately 220 feet of organic and gas rich Haynesville and its been completed in the vertical section with an initial IP of just over one million cubit feet of gas per day.

Our plans for the initial phase of Haynesville development is to drill a number of strategically located Haynesville verticals across our acreage which will allow us to enhance the design and plans for future horizontal drilling. I would now like to turn the call over to Rob Turnham

Robert Turnham

We continue to be focused on production volume and reserve growth for the drill bit in the first quarter though it was certainly a very good quarter on both fronts. Our Cotton Valley gross production volumes grew to a record 110 million cubit feet equivalent per day and as Gil stated earlier net volumes for the quarter averaged approximately 58 million per day which was above the upper end of our guidance and a 15% sequential growth rate over the fourth quarter.

We had 292 Cotton Valley trend wells producing as we exited the quarter with 13 in completion phase bringing the total to 305 wells drilled along with the success rate in excess of 99%. Of the 292 producing wells 95 were in Minden, 69 at Beckville, 50 in the Angelina River trend, 37 at Bethany-Longstreet, 26 at South Henderson and 15 on other acreage outside of our core areas.

We conducted drilling operations on 41 wells during the quarter with approximately 11 rigs running nine of which we operated. Of the 41 wells in which we conducted drilling operations 16 were drilled in Angelina River with 13 being Travis Peak wells and three being James Lime horizontal, nine were at Minden, two at Beckville, six at South Henderson, seven at Bethany-Longstreet and one at Longwood.

For the quarter we completed 35 wells in six fields with an average initial production rate in excess of 2.2 million cubit feet equivalent per day which is 340 Mcfe per day higher or about 20% higher than our historical average. Of the 35 wells completed during the quarter 12 were in Angelina River with an average IP rate of three million cubit feet per day.

Seven were at Minden with an average IP of 1.8 million per day, five at Bethany-Longstreet with an average IP rate of 1.5 million per day, four at Beckville with an average IP rate of 1.7 million a day, five at South Henderson at 2.4 million per day and two were in other fields.

Our drilling plans for 2008 will continue to be focused on a number of catalysts. First we will continue to drill in proven areas of our core Cotton Valley acreage both on 40 acre vertical spacing and 20 acre vertical spacing. We will also continue to aggressively drill our Travis Peak wells and Angelina River to not only grow production volumes and reserves but to delineate or de-risk the acreage block as well.

We will continue to test horizontal application on our acreage on data sand of the Cotton Valley as well as the James Lime formation in Angelina River and the Hanesville Shale at both Bethany-Longstreet and Longwood. At Bethany-Longstreet we’re currently competing our champ gram 5H a Cotton Valley horizontal well targeting the data sand similar to our champ gram 3H and expect results within 30 days.

Netherland Sewell continues to do our reserves and at year end we had proved developed reserves on the champ gram 3H of 3.9 Bcfe and are targeting similar results on the 5H. For the Haynesville Shale we are currently drilling our second pilot vertical well at Bethany-Longstreet to Clarence Brown number one and expect to have production results in about 60 days. As Gil stated earlier our plans to drill a handful of pilot vertical Haynesville Shale wells in the field before commencing horizontal development later this year.

At Longwood again which is North of Bethany-Longstreet still in Caddo Parish and well within the Angel Shale play we have plans to reenter an existing vertical well and drill two additional vertical wells down to the Haynesville by the end of the year. As is the case at Bethany-Longstreet these vertical wells will serve as pilot wells which will souse up for horizontal development at a later date.

Moving to Texas, we continue to focus more and more of our efforts in Angelina River trend where we on an average 58% working interest and 70,000 growths or 40,500 net acres. This area has substantial potential with the company and we have plays working simultaneously. Travis Peak vertical wells which are typically drilled to a little less than 12,000 feet and horizontal James Lime wells we see at about 9,000 feet.

For the quarter we participated in drilling operations on 13 vertical Travis Peak wells and completed all of which has the James Lime present with gas yes. Our James Lime development was a little slow in the quarter than anticipated due to non-operated rig moving out of the field for most of the quarter as well as delay on fracting our Henderson 1H well in the Cotton prospect area due to the expected delay at five mile pipeline.

The non-operated rig is now back and drilling. Our Ramos 1H well on our Cotton prospect acres and we are currently drilling our Kirkland 2H with one of our operated rig and pulling our Allentown prospect area. We plan on studying our initial James Lime horizontal well in our Cotton South prospect area in the second quarter and are encourage by results from on offset operator just west of our Cotton South acres as well as good gas in each of our Travis Peak wells drilled to date in the area.

We do not have any reserve exposure built into our prospect inventory currently because James Lime at Cotton South but will do so to include the impact in our upcoming management presentations with positive results from this well.

We continue to see very good results in the Southeastern portion of our Minden block as well as South Henderson and plan to drill our first 20 acre spaced well at South Henderson later this year. Again currently we’re looking at our drilling inventory of un-risk reserve exposure we have not accounted for any reserves based on 20 acre spacing at South Henderson.

I would like to now turn it over to David Looney to walk you through the financials.

David Looney

Reported revenues for the first quarter of 2008 of $46.4 million were based on average prices of $8.44 per Mcf of gas and $96.15 per barrel of oil. On gas our differential was approximately $0.20 below the average Henry hub price during the quarter which was within the range of $0.20 to $0.50 we expect to see.

On oil we realized an average basis of $1.61 off of WTI Cushing prices during the quarter. These prices do not include the impact of $300,000 in realized gains on our hedging portfolio during the quarter. During the quarter all of our gas and oil hedges were deemed ineffective thus changes in the mark to market value of the contracts must run through the line item gain or loss on derivatives not designated as hedges.

Looking at cash flow our EBITDAX for the first quarter 2008 increased to $32.3 million or $1.02 per basic share versus $17.7 million or $0.71 per basic share for the prior year period. Discretionary cash flow defined as net cash from operations before changes in working capital increased to $28.9 million for the quarter versus $19.9 million during the first quarter 2007.

Focusing on the expense side of the income statement our lease operating expenses in the first quarter were approximately $7.1 million or $1.35 per Mcfe on the unit basis versus $4.1 million or $1.23 per Mcfe in the first quarter of 2007 and $6.9 million of $1.50 per Mcfe in the fourth quarter 2007. LOE for the first quarter 2008 included $0.18 per Mcfe for work over expenses versus only $0.04 per Mcfe for work overs during the first quarter ’07.

Excluding the impact of work over and abandonment expenses the LOE per Mcfe was a constant rate at $1.17 per Mcfe in each of the first quarter 2008 and 2007. As a reminder we previously stated guidance for the first quarter 2008 LOE of between $1.10 and $1.30 per Mcfe before LOE and $0.15 per Mcfe for work overs for a total of $1.25 to $1.45 per Mcfe in total. Thus we were right in the midpoint of this range for the quarter.

Over the next several quarters we do not expect to see any material change in this per unit expense until new salt water disposable facilities are in place by the end of the third quarter in our North Minden field and the Cotton South area of the Angelina River trend.

Production and other taxes of $1.3 million for the first quarter of 2008 included production tax of $0.8 million and add more taxes of $0.4 million. Production taxes were net of $0.9 million of tight gas sands credits we booked for our wells in the State of Texas during the quarter.

By comparison during the first quarter 2007 we booked $800,000 of TGS credits against a much lower production base thus resulting in the lower level of absolute and per Mcfe production taxes in that earlier comparable quarter. It would be $0.3 million for the quarter and $0.09 per Mcfe in the first quarter ’07 for comparison. You’ll recall that the first quarter of ’07 was the first quarter in which we booked what we would consider a material amount of TGS credits due largely to a greater number of backlog credit being approved by the State of Texas.

Again as a reminder these credits allow for reduced and in many cases the complete elimination of severance taxes in the State of Texas for qualifying wells for up to 10 years of production and we only accrue for such credits once we’ve been notified of the states approval. As such we anticipate we’ll incur a gradually lower production tax rate in the future as we add additional Cotton Valley trend wells to our production base and reduced rates are approved.

Transportation expenses totaled $1.9 million in the first quarter 2008 or $0.36 per Mcfe versus $1.1 million or $0.32 per Mcfe in the first quarter 2007. However, the $0.36 per Mcfe number for this quarter was slightly lower than that seen in the fourth quarter 2007 of $0.37 per Mcfe. As a sequential quarterly numbers would indicate our current production mix is resulting in a fairly level range of per Mcfe transportation expenses from $0.35 to $0.45 in the after mill.

DD&A totaled $25.1 million for the first quarter 2008 or $4.76 per Mcfe versus $17.7 million or $5.28 per Mcfe in the first quarter 2007 and $22.2 million or $4.77 per Mcfe for the fourth quarter 2007. We calculated the first quarter DD&A rates using the December 31, 2007 reserve information. Just to remind everyone that we as a successful efforts company are required to complete our total capitalized drilling and completion costs over only the proved developed portion of our reserves.

Expiration expenses for the first quarter 2008 decreased to $2.0 million or $0.38 per Mcfe from $2.3 million or $0.69 per Mcfe for the first quarter 2007 due primarily to a decrease in the amortization of undeveloped legal costs from $1.8 million in the first quarter of 2007 to $1.6 million in the first quarter of this year. As a reminder as new areas are developed and proven successful the resulting acreage costs per transfer to the proved producing category and included in the DD&A rate.

G&A expense remained relatively flat at $5.4 million during the first quarter of ’08 versus $5.3 million during the first quarter 2007 and $4.9 million during the fourth quarter of ’07. On a per unit basis G&A declined $1.03 per Mcfe during the first quarter of 2008 versus $1.59 per Mcfe during first quarter of 2007 primarily due to the 57% increase in production volumes.

Stock based compensation expense which is a non-cash item amounted to $1.3 million for the first quarter of this year versus $1.4 million for the prior year period. As we pointed out on previous calls our cash G&A expense has been relatively flat for the last five quarters averaging approximately $4 million per quarter during this period.

Finally, for the three months ended March 31, 2008, we reported a net loss applicable to common stock of $25.4 million or $0.80 per basic share on total revenue from continuing operations of $46.4 million which compares to a net loss applicable to common stock of $0.5 million or $0.02 per basic share on total revenue from continuing operations of $23.5 million for the three months ended March 31, 2007. The majority of this year’s loss resulted from a $24.7 million loss on derivatives not designed as hedges during the quarter.

Turning to the balance sheet with a new borrowing base of $175 million which is based on the December 31, 2007 reserve report and only $34 million outstanding as of March 31st Goodrich is in the best liquidity position it has been for a long time. The combination of our December 2007 equity offering and the January 2008 second lien term loan raised approximately $200 million net to the company.

When you combine these proceeds with the increased bank revolve availability and our internal cash flow we proceed to be going well into 2009 before the company will need another external capital raise. We would certainly expect to receive another borrowing base increase during the third quarter of this year after our mid year reserve report given our past track record with the bank. Having said that we actively exploring other possible sources of finance including the possible sale of certain non-core properties to help reduce the long term funding needs of the company going forward.

With that I’ll now turn it back to Gil for some closing comments.

Gil Goodrich

As I said in my opening comments we are pleased with the operational progress achieved during the quarter. We believe we can and will continue to make progress in that regard. Finally, while we will not take our eye off the ball with regard to our core operating activity we are excited about our plans to exploit the Hanesville Shale across our acreage.

On the Hanesville how many vertical are you planning on drilling before the horizontal location is selected in the third quarter?

Gil Goodrich

It’s difficult to give a precise number but a handful probably five to six wells and that would be scattered between both Bethany-Longstreet and our Longwood Block in Northern Caddo Parish.

Kim Pacanovsky – Collins Stewart

I assume that’s the step out into more into the East Texas area would be after perhaps some other operators had data from those areas?

Gil Goodrich

It is a good bit of activity going on over in and around our East Texas acreage and I think what I’d like to say at this point is that we have plans to continue with exploiting the Hanesville there as well. A little early to draw a circle around it and put the bulls out on it that we have in Caddo and the other Parishes that we have in our mind but we certainly see potential there and have not ruled it out by any means.

Kim Pacanovsky – Collins Stewart

At what time of year do you renegotiate your pressure pumping contract?

Gil Goodrich

We usually do that in December for the following calendar year.

Robert Turnham

That’s the benefit of what we’re experiencing right now we have an increasing gas price and we’re locked in on pressure pumping among other completion costs for the full calendar year ’08.

Kim Pacanovsky – Collins Stewart

When there was the huge differential on the Rockies a lot of those Rockies crews came into the East Texas area are you seeing, I know that you’re locked in for the year but are you seeing any kind of tightening as perhaps crews are moving back in to the Rockies for higher prices there?

Robert Turnham

We’re seeing tightening throughout the industry not just pressure pumping due to additional activity but certainly on two do goods, heightened activity levels tend to put more pressure on it. We have the benefit of not having to go out and price any of those completion operations but that’s what we’re hearing.

Operator

Your next question comes from Joe Allman – JP Morgan.

Joe Allman – JP Morgan

You guys spent more than you thought during the first quarter would you expect to be bumping up the CapEx budget based on that and if not what’s going to be the change going forward?

Gil Goodrich

Yes, we certainly are cognizant of the fact that the first quarter CapEx numbers came out roughly about $10 million ahead of the budget if you just slice it up into four quarters. As we said with the record level of activity conducting operation of 41 wells that really was the driver to that. We’re reviewing that; the biggest swing would be the non-operated activities which were on an up tick.

We think that will moderate a little bit over the next couple of quarters on the non-op piece. Its really difficult to say to the extent which we might be over 275 at this point but I would tell you given where gas prices are we certainly would prefer to stay with the level of activity and that might require some upward movement in our budget and we’ll be reviewing that with the Board here in a couple weeks.

Joe Allman – JP Morgan

In reference to Kim’s question on pressure pumping and then your answer there. On pressure pumping just to clarify you guys are locked in on anything to do even if you step up activity for the full year and then also just talk about are you seeing tightening increases in rig rates and other services can you comment on that.

Gil Goodrich

That’s correct, we fixed the rates on pressure pumping for the full calendar year so whether we drill 90 or we drill 120 wells that rate for the completion operations sticks. That will be renegotiated and put out for bit in December of this year for the 2009 business. We expect certainly if gas prices stay in the area where they are today that that will tighten and those rates will be coming back up by the time we get around to renegotiating it.

In terms of rigs we’re seeing what I would call very modest up tick. We mentioned on our last call we had renewed drilling contracts on I believe it was five rigs in the second half of 2007 at roughly about a $15,500 per day rate. We keep a finger on that market and I would say today arguably for about a thousand horse power rig it might be $16,000 but it wouldn’t be any appreciably higher than that.

Again, that’s a market we’re watching very closely. We have three rigs that will be coming up for renewal during the summer I think June, July, and August. Today it’s not up a whole lot.

Joe Allman – JP Morgan

Lastly it seems like your sending a message here like you’ve got no intensions of accessing the external financing during 2008. The risk would be the market turns south going forward you had an opportunity here with the market the way it is to get some money here. Am I right that’s the message your saying you have no intention of anything this year and really looking to sell some assets and you’ll revisit well into 2009?

Gil Goodrich

I would say that we’re not trying to telegraph anything. We’re saying that we’re comfortable given the portfolio of opportunity across our acreage to raise some incremental capital in addition to the increasing cash flow that we’re experiencing as well as our bank credit facility that we can continue to execute our strategy. Whether or not we would decide to do something different particularly if capital market transaction would be depending upon a number of factors and would certainly be a decision that our Board would make. We’re not ruling anything in or out at this point in time.

Operator

Your next question comes from Ellen Hannan - Bear Stearns.

Ellen Hannan - Bear Stearns

Do you have an idea of how much capital you’re going to target toward drilling in Hanesville this year?

Gil Goodrich

That’s a great question and the simple answer would be not exactly. At this point in time we’re drilling these pilots and the pilots will dictate not only where we drill but how much we drill. We are evaluating those early data points as well obviously offset activity to better get our arms around initial rates, early decline curves, ultimate EURs everything that we’re hearing is very positive but we’re still waiting to see some reported numbers and that will be the big driver in terms of how much capital.

At this point it’s fairly easy for us as we’re doing well in the Cotton Valley anyway and so about a day and a half drilling time we can get to the Hanesville from the base of the Cotton Valley. We’re really in a data collection mode with some incremental reallocation with rigs in Hanesville second half. It would be less than $10 million.

Ellen Hannan - Bear Stearns

The credit facility, the increase you have, how much can you draw on that?

David Looney

We can draw up to the full amount the full $175 million.

Ellen Hannan - Bear Stearns

You have nothing drawn now.

David Looney

No, at March 31st which we reported we had $34 million drawn.

Ellen Hannan - Bear Stearns

I know that historically you looked at a mid year reserve update with Netherland Schule do you have an idea of what you think is a reasonable objective for your reserve adds for the first year exit anything that you might come up with out of the Hanesville.

Gil Goodrich

Generally respond by saying we never like to get in front of our reserve engineers to make predictions about what they’ll come up with. I would say that if you looked at the move in the second half of last year where we went from 302 Bcfe to 358 Bcfe fairly meaningful increase in prove reserves. In the rear view mirror yard stick I say that’d be a reasonable guess at this point in time.

Operator

Your next question comes from Stacy Nieuwoudt – Tudor Pickering.

Stacy Nieuwoudt – Tudor Pickering

I wanted to follow up on the CapEx question. Now that you’re reallocating some capital to the Hanesville could you walk us through your plans for capital allocation on the Cotton Valley, James Lime and Hanesville and how many rigs in each area?

Robert Turnham

We just updated our management presentation and within that as you know we had an inventory chart that allocates number of wells being drilled in ’08. We’ve updated it with an estimate of Hanesville shale wells. I believe Gil is correct; we have maybe six wells in the budget for ’08 now in the Hanesville. Except for maybe spudding one horizontal well by the end of the third quarter the rest of those wells would be vertical wells and we just basically taken that out of the Beckville Minden area.

We still have a budget of 115 wells for ’08. You’ll see a breakdown of that in our management presentation which is on our website today.

Stacy Nieuwoudt – Tudor Pickering

Any change to your CapEx allocated to lease hold acquisitions?

Robert Turnham

We’re still budgeting the $30 million that is both lease hold acquisition and gas gathering. As you can imagine North Louisiana the price per acre has escalated pretty dramatically. We were in the field attempting to add to our longwood position and we’re certainly not the type of company that will chase it regardless of acreage costs. We feel comfortable that the $30 million is still a good number.

Stacy Nieuwoudt – Tudor Pickering

On leasing rates Hanesville what are your current leasing rates?

Gil Goodrich

We hate to get on the record saying anything because a lot of what we’re hearing is second and third hand information. Just to give you a general yard stick we were a year ago you probably could have leased it for a couple hundred dollars an acre that has certainly got into multiples of thousands of dollars per acre, $5,000 to $10,000 is not unheard of. It’s a general range, is it going to go to $10,000, perhaps could be there today, will it go higher, only time will tell.

Stacy Nieuwoudt – Tudor Pickering

Can you give us your current rate of production today and any reason why we wouldn’t see nice sequential up tick in Q2 versus Q1?

Gil Goodrich

We cannot give you current production that’s not something we do. We did give you guidance, I believe in the press release for 5% to 9% sequential growth expectation for 2Q over 1Q.

Operator

Your next question comes from Ron Mills - Johnson Rice.

Ron Mills - Johnson Rice

A question as it relates to sell order disposal system and the installation. What kind of cost improvement do you think you can achieve? I know initially you were hoping to get operating costs back down to the low dollar per Mcfe. Once that system is up and running is that a goal that we can look forward to at some point in the middle part of ’09?

Gil Goodrich

It’s very difficult, David gave some pretty good guidance there as to the range we expect and we said here recently that we do expect the LOE and particularly salt water disposable trend to be a downward trend but it will be kind of lumpy. The reason it will be lumpy is that we’re continuing to step out into new areas which do not have any infrastructure in them. We will see some incremental up tick in costs in certain geographic areas at the same time we’re making progress in others.

If we had just one little core area that’s all we were doing was drilling in that tight little band we could drive this thing down considerably faster and more and give you better guidance. I think that David’s guidance is pretty good for right now.

Ron Mills - Johnson Rice

His guidance it seemed like pretty flattish for the second and third quarters but correct me if I’m wrong I think you were suggesting some improvements in the fourth quarter is that correct.

David Looney

That right. We’re seeing pretty much the same as what you saw in the first quarter for the second and third and we do expect some improvement in the fourth. We haven’t put a number on that because timing of some of these facilities is critical in a dry bed.

Ron Mills - Johnson Rice

In East Texas the 20 acre infill drilling program on your inventory side are the wells broken down in terms of number of wells you plan on infill drilling or if not what’s that activity level expected to be. Any color on the results to date.

Robert Turnham

We really had no additional 20 acre space wells drilled in the first quarter. Most of the previous 20 acres space wells were drilled in Beckville and Minden. I think we had seven wells that we reported on that were drilled and completed in the fourth quarter with an average EUR of about 1.1 Bcf basically identical to the offset wells. Everything in our mind in those two areas is until drilling. We’ve spread those wells out and de-risk the acreage so if you look at our presentation you’ll see that we’re coming back in between well bores and drilling wells. Whether its 40 or 20 really the risk profile is the same.

What probably is meaningful is that it would step out and drill in South Henderson on 20 acre spacing and that work similar to what we saw in Minden and Beckville that certainly would add reserve exposure in that particular field that’s not currently accounted for. We’re not seeing any communication on wells that we’ve drilled to date on 20 acre spacing its just again a challenge to allocate your rigs with so much to do and so many good areas what we want to do is prove that 20 acre spacing works but we have a long way to go before we get down to actually drilling only in 20 acres space wells.

Ron Mills - Johnson Rice

On the vertical Hanesville beeping that you already completed it sounds like you actually completed that well to get a vertical test rate. At some point do you think you will release that test rate and secondly what drove the decision to actually complete it whether it was just to collect more data than just what logging and gores would have provided?

Gil Goodrich

My feeling are hurt you weren’t listening to me. I said we tested at a little over a million a day. We tested the well at a little over a million a day which was certainly well within the range of the expectations. I would say that this is a horizontal play not much question about it, it’s a horizontal play. The verticals help us in that we’re gathering data and information as I said at the outset for horizontal drilling down the road.

In addition to that particularly at Hosston where we had Hosston and the Cotton Valley already productive being able to add the incremental reserves in production from the Hanesville was just a bonus and we believe that the incremental costs matched against the incremental reserve looks like at least early for us looks like a win situation and we will continue to drill some vertical wells to the Hanesville and add that in incremental production.

Ron Mills - Johnson Rice

So you’re able to commingle or is it dependent on some of the Hanesville pressure?

Gil Goodrich

The big obstacle is the regulatory issues. We’ve got some regulatory issues we’ve got to go through to be able to commingle that. We believe ultimately that we will be able to do that and so right now. To answer the second part of your question the pressure, we want to product off the pressure from the Hanesville a little bit initially before you went to commingling but you could probably do that in a few months time.

Ron Mills - Johnson Rice

To refresh my memory I think it was to actually do a completion, to deepen the cost probably another 250,000 to 300,000 but to complete it its another couple hundred thousand so you were looking at $.5 million costs?

Gil Goodrich

Yes, I would say I’ve seen some numbers out there that were lower than that but in our minds kind of $400,000 to $500,000 of incremental costs.

Ron Mills - Johnson Rice

And $1 million a day and so from a reserve if it behaves like the Cotton Valley or other type gas then that incremental $.5 million looks like a pretty good investment especially given the data collection.

Gil Goodrich

Exactly right. You start getting even a quarter of a Bcf and you’re making money. You get a pretty little fine in development costs on that incremental dollar.

Ron Mills - Johnson Rice

You talked about on the 1,000 horsepower rig the rate is ticking up just a little bit are those rigs going to be significant enough to execute a horizontal drilling program in Louisiana or are you going to need probably maybe even 1,500 or 2,000 horsepower rigs? What’s that market looking like?

Robert Turnham

Currently we have about three to four of our rigs that have top drives that potentially could drill horizontal wells but the bigger rigs certainly work better probably 1,300 horsepower or greater could potentially do that, certainly a 1,500 horsepower rig would be probably the optimum size. What we do know is that when drilling in shale it does appear to drill a little bit easier than our horizontal Cotton Valley wells just due to the rock quality. You need to top drive and you need at least 1,200 to 1,300 horsepower.

That market is probably not a whole lot different, maybe a little tighter than 1,000 horsepower market. Of course you’re going to have to pay a little bit more maybe more like $17,000 a day versus the $16,000. Maybe $17,500 a day for the larger size rig.

I would like to ask what is the cost of drilling a horizontal well in the Hanesville in a typical location. How does that compare with drilling a horizontal well in the Cotton Valley?

Robert Turnham

We’re seeing a range from our competitors of $5.5 to $6.5 million to drill these horizontal wells in the Hanesville. Not a whole lot different than the Cotton Valley. It does sit roughly 1,000 to 1,500 feet deeper but it does appear to drill a little bit quicker than the Cotton Valley horizontal wells. Hopefully once you go lateral, hit horizontal you could make up a little extra time to basically get those completed well costs in a similar range.

Bruce Brewster – Brewster Asset Management

Unlike vertical wells going down to the Hanes to the Cotton Valley cannot be accomplished the same well bore right?

Robert Turnham

You mean an existing well bore?

Bruce Brewster – Brewster Asset Management

No, I mean after you’ve made the expenditure to drill the Cotton Valley horizontally there’s no potential to test on a horizontal well in the Hanesville as well from the same drill bore?

Robert Turnham

Yes, I think mechanically that would be pretty difficult to go deeper and then go laterally out of that well.

Bruce Brewster – Brewster Asset Management

The vertical wells in the Hanesville you sort of present these as a test wells are they also economical do you feel? You say they’re definitely better prospects so horizontal wells but are they also economical as vertical wells?

Gil Goodrich

Yes, in answer to your previous question Ron Mills at Johnson Rice I said that the incremental costs of the vertical. The Hanesville looked like more than offset by the incremental reserves based on our very early test information.

Robert Turnham

You could spend $500,000 incremental and get 250 million cubit feet that would be a $2.00 fining costs would be attractive.

On the production tax exemptions do you think you’ll be getting them on most all of your East Texas as wells, are you getting any feedback on that?

David Looney

We started at the Cotton Valley and we’ve been getting them on Cotton Valley for a while. We’ve just started getting some of those exemptions now or credits back on the Travis Peak wells so that is correct.

Richard Tullis - Capital One Southcoast

What about the Angelina River, James Lime?

David Looney

Yes, same there.

Richard Tullis - Capital One Southcoast

Looking at the James Lime what are you looking at now for EUR and costs, any change there?

Robert Turnham

Our expectations over the play again are still at about 2.5 Bcf per well over time there will be some higher ones and some lower ones and we’re spending we and our competitors appear to be spending anywhere from $3.5 to $4 million would be our expectations on completed well costs.

Richard Tullis - Capital One Southcoast

Were there any non-op James Limes brought on in 1Q?

Robert Turnham

No and that’s basically what created the slow down. We may have broadly well but we certainly weren’t drilling any wells. The LB Mast 1H was brought online early in the quarter we don’t have an exact date but our joint venture partner took that rig out in essence we really didn’t have as many wells being drilled in the quarter as we had expected in fact the one that we spud our Henderson 1H good news is it sits out a good bit to the East of our other activity, our Cotton Prospect area the bad news is we had to lay a pretty long line gas pipeline to get to it.

Hopefully that pipeline will also serve as a number of horizontal wells in the Cotton Prospect area but it did cause a delay.

Operator

Your next question comes from Dan Mcspirit – BMO Capital Markets.

Dan Mcspirit – BMO Capital Markets

You speak to Bethany-Longstreet and the Longwood area as being prospective for the Hanesville shale how much of your acreage today do you estimate prospective for the Hanesville whether it’s in East Texas or North Louisiana?

Gil Goodrich

We certainly consider all of our acreage in Northwest Louisiana which is located, all of our acreage in North Louisiana is in Caddo or very northern DeSoto Parish and that certainly is in the bull’s eye area of most of the activity today. That would be about roughly 25,000 net acres to Goodrich Petroleum. Just East of there and on the West side of Carthage in very Western Panola and Eastern Rusk counties are Minden and Beckville Block.

Totals I believe are about 44,000 net acres and there is activity starting to pop up around there and we are, as I said in an earlier answer we are beginning to test and see what the Hanes looks like in that area. We would not at this point certainly consider all of that acreage as definitely productive but we certainly consider it as prospective.

Dan Mcspirit – BMO Capital Markets

Given the promise of the Hanesville today why not allocate or reallocate capital, move capital away from even a core businesses, the core drilling effort today and participate in the sale sweepstakes in the land grab that’s going on today in light of the promise of the Hanesville and what it could mean to Goodrich it being somewhat of a life altering event for any company involved in North Louisiana today?

Gil Goodrich

I assume you mean why are we, assuming that we are not out leasing new acreage, is that what you’re saying?

Dan Mcspirit – BMO Capital Markets

Right, why not be more aggressive, assuming you’re not?

Gil Goodrich

We would not at this point comment on what we are or are not doing relative to leasing in the area. We certainly are cognizant of the play and when we see opportunities that we think matches up a good risk reward based on what we know about the play at this point versus the costs to do that we are taking advantage of it. As we said earlier we are well underway with our plans to begin the exploitation of the Hanesville as it relates.

Operator

Your next question comes from John Freeman - Raymond James.

John Freeman - Raymond James

I just had a few remaining question focused on the James Lime. If I exclude the USLB well that St. Mary had the mechanical issues on and lease the well I’ve got in front of me the Wilson 4H, LB Mass, Middlebrook it looks like it had an average IP for those of around seven million a day. It seems like from when we first talked about this play like a year ago that’s easily exceeding Gil’s original expectation. I was wondering if the 2.5 Bcf you’re still sticking to is just ultra conservative number and it’s likely that goes higher.

Robert Turnham

It covers a big area. We have 70,000 acres. Cabbott, St. Mary, and Southwestern we’re all active in the play. We would feel more comfortable if we had more data points on our acreage before we updated that number and got more aggressive with it. We still feel pretty comfortable with it. If you drill a sampling of it that’s a reasonable number to get and again I said some might be higher, some might be lower and EURs than that.

Again, statistically that’s a reasonable number and if you can spend less than the $4 million to get a very attractive finding development cost. Also we’re still experimenting with completion techniques, how big of a frac to put on these wells versus spending less money in the economics associated completing wells cheaper. In fact we’re about to complete this Henderson 1H a little bit bigger frac on it to see the types of IP rates and ultimate recoverable reserves we get from that.

As we sit right now we’re still pretty comfortable with hopefully over time under promising and over delivering but we need more well data points before we can adjust those projected EURs.

John Freeman - Raymond James

Following up on the completion technique on the Henderson I know that the Wilson and the LB Mass were both longer laterals H to H frac I remember on the LB Mass and you said you’re going to do a bitter frac on the Henderson but it’s a shorter lateral maybe just elaborate on that decision.

Gil Goodrich

When he says bigger jobs he’s referring to volumes of fluid pump and span concentration put away into the formation. Though we might have a little bit shorter laterals its really about volume of the job itself.

John Freeman - Raymond James

You mentioned you are drilling 13 vertical Travis Peak and saw the James Lime and all those just refresh my memory have you drilled any wells in Travis Peak where you haven’t seen the James Lime?

Gil Goodrich

No, we’ve seen the James lime across the spectrum of our acreage in Angelina River. The gas wells are a little different from place to place so I would say that we certainly are not, we will 100% of our Angelina acreage in at this point relative to the James but there’s little to none we would rule out as well. We’re concentrating those areas where we’ve had the best initial results and the offset production has been the best still stepping out and proving up a lot of acres. We’re in the very early stages relative to the James of proving up that across our acreage.

Robert Turnham

If you remember we’d only included 50% of our acreage in our inventory currently and again just waiting to step out and drill these wells in these other areas before we start factoring that in both on the Travis Peak and the James Lime. The James Lime we again only accounted for about 50% of our acreage in our inventory.

Operator

Your next question comes from Mike Tapp – Longhorn Capital.

Mike Tapp – Longhorn Capital

I was hoping maybe you could give us a little more color around non-core assets that you might consider monetizing or give us some idea of the order of magnitude of capital that you would hope to be able to raise to supplement or augment your drilling program.

Robert Turnham

One of the fields that we often talked about is South Henderson still there’s a good bit of potential there but certainly is a run off field from our more contiguous Beckville Minden area, Angelina River Trend and then of course North Louisiana. Year end we had 30 Bcfe approved reserves about 90 Bcfe of probable reserves there. It does have 20 acre spacing potential also so certainly its in an area that is in high demand its just an area where we’re only going to drill 10 to 12 wells, probably 12 wells this year relative to the 115 and it comprises I would say a little over 10% of our production.

Currently all gas, certainly natural gas prices right now would allude to the fact that we could potentially get a pretty good number for that. We have not made that final decision yet as to whether to sell properties but that would certainly be at the top of the list if you were looking at non-core, non-strategic areas.

Operator

This does conclude the question and answer portion of today’s conference call.

Gil Goodrich

Thank you very much everyone we appreciate your participation in the call this morning and we look forward to reporting second quarter results to you late this summer.

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